1. Field of the Invention
The present invention relates to rotating control devices used when drilling wells and methods for use of these rotating control devices.
2. Description of the Related Art
Rotating control devices (RCDs) have been used for many years in the drilling industry for drilling wells. An internal sealing element fixed with an internal member of the RCD seals around the outside diameter of a tubular and rotates with the tubular. The tubular may be slidingly run through the RCD as the tubular rotates or when the tubular, such as a drill string, casing or coil tubing is not rotating. Examples of some proposed RCDs are shown in U.S. Pat. Nos. 5,213,158; 5,647,444 and 5,662,181. The internal sealing element may be passive or active. Passive sealing elements, such as stripper rubber sealing elements, can be fabricated with a desired stretch-fit. The wellbore pressure in the annulus acts on the cone shaped stripper rubber sealing elements with vector forces that augment a closing force of the stripper rubber sealing elements around the tubular. An example of a proposed stripper rubber sealing element is shown in U.S. Pat. No. 5,901,964. RCDs have been proposed with a single stripper rubber sealing element, as in U.S. Pat. Nos. 4,500,094 and 6,547,002; and Pub. No. US 2007/0163784, and with dual stripper rubber sealing elements, as in the '158 patent, '444 patent and the '181 patent, and U.S. Pat. No. 7,448,454. U.S. Pat. No. 6,230,824 proposes two opposed stripper rubber sealing elements, the lower sealing element positioned in an axially downward, and the upper sealing element positioned in an axially upward (see FIGS. 4B and 4C of '824 patent).
Unlike a stripper rubber sealing element, an active sealing element typically requires a remote-to-the-tool source of hydraulic or other energy to open or close the sealing element around the outside diameter of the tubular. An active sealing element can be deactivated to reduce or eliminate the sealing forces of the sealing element with the tubular. RCDs have been proposed with a single active sealing element, as in the '784 publication, and with a stripper rubber sealing element in combination with an active sealing element, as in U.S. Pat. Nos. 6,016,880 and 7,258,171 (both with a lower stripper rubber sealing element and an upper active sealing element), and Pub. No. US 2005/0241833 (with lower active sealing element and upper stripper rubber sealing element).
A tubular typically comprises sections with varying outer surface diameters. RCD passive and active sealing elements must seal around all of the rough and irregular surfaces of the components of the tubular, such as hardening surfaces (such as proposed in U.S. Pat. No. 6,375,895), drill pipe, tool joints, and drill collars. The continuous movement of the tubular through the sealing element while the sealing element is under pressure causes wear of the interior sealing surface of the sealing element. When drilling with a dual annular sealing element RCD, the lower of the two sealing elements is typically exposed to the majority of the pressurized fluid and cuttings returning from the wellbore, which communicate with the lower surface of the lower sealing element body. The upper sealing element is exposed to the fluid that is not blocked by the lower sealing element. When the lower sealing element blocks all of the pressurized fluid, the lower sealing element is exposed to a significant pressure differential across its body since its upper surface is essentially at atmospheric pressure when used on land or atop a riser. The highest demand on the RCD sealing elements occurs when tripping the tubular out of the wellbore under high pressure.
American Petroleum Institute Specification 16RCD (API-16RCD) entitled “Specification for Drill Through Equipment—Rotating Control Devices,” First Edition, © February 2005 American Petroleum Institute, proposes standards for safe and functionally interchangeable RCDs. The requirements for API-16RCD must be complied with when moving the drill string through a RCD in a pressurized wellbore. The sealing element is inherently limited in the number of times it can be fatigued with tool joints that pass under high differential pressure conditions. Of course, the deeper the wellbores are drilled, the more tool joints that will be stripped through sealing elements, some under high pressure.
In more recent years, RCDs have been used to contain annular fluids under pressure, and thereby manage the pressure within the wellbore relative to the pressure in the surrounding earth formation. During such use, the sealing element in the RCD can be exposed to extreme wellbore fluid pressure variations and conditions. In some circumstances, it may be desirable to drill in an underbalanced condition, which facilitates production of formation fluid to the surface of the wellbore since the formation pressure is higher than the wellbore pressure. U.S. Pat. No. 7,448,454 proposes underbalanced drilling with an RCD. At other times, it may be desirable to drill in an overbalanced condition, which helps to control the well and prevent blowouts since the wellbore pressure is greater than the formation pressure. While Pub. No. US 2006/0157282 generally proposes Managed Pressure Drilling (MPD), International Pub. No. WO 2007/092956 proposes Managed Pressure Drilling (MPD) with an RCD. Managed Pressure Drilling (MPD) is an adaptive drilling process used to control the annulus pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the hydraulic annulus pressure profile accordingly.
One equation used in the drilling industry to determine the equivalent weight of the mud and cuttings in the wellbore when circulating with the rig mud pumps on is:Equivalent Mud Weight (EMW)=Mud Weight Hydrostatic Head+Δ Circulating Annulus Friction Pressure (AFP)This equation would be changed to conform the units of measurements as needed.In one variation of MPD, the above Circulating Annulus Friction Pressure (AFP), with the rig mud pumps on, is swapped for an increase of surface backpressure, with the rig mud pumps off, resulting in a Constant Bottomhole Pressure (CBHP) variation of MPD, or a constant EMW, whether the mud pumps are circulating or not. Another variation of MPD is proposed in U.S. Pat. No. 7,237,623 for a method where a predetermined column height of heavy viscous mud (most often called kill fluid) is pumped into the annulus. This mud cap controls drilling fluid and cuttings from returning to surface. This pressurized mud cap drilling method is sometimes referred to as bull heading or drilling blind.
The CBHP MPD variation is achieved using non-return valves (e.g., check valves) on the influent or front end of the drill string, an RCD and a pressure regulator, such as a drilling choke valve, on the effluent or back return side of the system. One such drilling choke valve is proposed in U.S. Pat. No. 4,355,784. A commercial hydraulically operated choke valve is sold by M-I Swaco of Houston, Tex. under the name SUPER AUTOCHOKE. Also, Secure Drilling International, L.P. of Houston, Tex., now owned by Weatherford International, Inc., has developed an electronic operated automatic choke valve that could be used with its underbalanced drilling system proposed in U.S. Pat. Nos. 7,044,237; 7,278,496 and 7,367,411 and Pub. No. US2008/0041149 A1. In summary, in the past, an operator of a well has used a manual choke valve, a semi-automatic choke valve and/or a fully automatic choke valve for an MPD program.
Generally, the CBHP MPD variation is accomplished with the choke valve open when circulating and the choke valve closed when not circulating. In CBHP MPD, sometimes there is a 10 choke-closing pressure setting when shutting down the rig mud pumps, and a 10 choke-opening setting when starting them up. The mud weight may be changed occasionally as the well is drilled deeper when circulating with the choke valve open so the well does not flow. Surface backpressure, within the available pressure containment capability rating of an RCD as discussed below, is used when the pumps are turned off (resulting in no AFP) during the making of pipe connections to keep the well from flowing. Also, in a typical CBHP application, the mud weight is reduced by about 0.5 ppg from conventional drilling mud weight for the similar environment. Applying the above EMW equation, the operator navigates generally within a shifting drilling window, defined by the pore pressure and fracture pressure of the formation, by swapping surface backpressure, for when the pumps are off and the AFP is eliminated, to achieve CBHP.
As discussed above, the CBHP MPD variation can only apply surface backpressure within the available pressure containment rating of an RCD. Pressure test results before the Feb. 6, 1997 filing date of the '964 patent for the Williams Model 7100 RCD disclose stripper rubber sealing element failures at working pressures above 2500 psi (17,237 kPa) when the drill string is rotating. The Williams Model 7100 RCD with 7 inch (17.8 cm) ID is designed for a static pressure of 5000 psi (34,474 kPa) when the drill pipe is not rotating. The Williams Model 7100 RCD is available from Weatherford International of Houston, Tex. Weatherford International also manufactures a Model 7800 RCD and a Model 7900 RCD. FIG. 6 is a pressure rating graph for the Weatherford Model 7800 RCD that shows wellbore pressure in pounds per square inch (psi) on the vertical axis, and RCD rotational speed in revolutions per minute (RPM) on the horizontal axis. The maximum allowable wellbore pressure without exceeding operational limits for the Weatherford Model 7800 RCD is 2500 psi (17,237 kPa) for rotational speeds of 100 RPM or less. The maximum allowable pressure decreases for higher rotational speeds. Like the Williams Model 7100 RCD, the Weatherford Model 7800 RCD has a maximum allowable static pressure of 5000 psi (34,474 kPa). The Williams Model 7100 RCD and the Weatherford Model 7800 and Model 7900 RCDs all have passive sealing elements. Weatherford also manufactures a lower pressure Model 7875 self-lubricated RCD bearing assembly with top and bottom flanges and a lower pressure Model 7875 self-lubricated bell nipple insert RCD bearing assembly with a bottom flange only. Since neither Model 7875 has means of circulating coolant to remove frictional heat, their pressure vs. RPM ratings are lower than the Model 7800 and the Model 7900. Weatherford also manufactures an active sealing element RCD, RBOP 5K RCD with 7 inch ID, which has a maximum allowable stripping pressure of 2500 psi, maximum rotating pressure of 3500 psi (24,132 kPa), and maximum static pressure of 5000 psi.
Pressure differential systems have been proposed for use with RCD components in the past. For example, U.S. Pat. No. 5,348,107 proposes a pressurized lubricant system to lubricate certain seals that are exposed to wellbore fluid pressures. However, unlike the RCD tubular sealing elements discussed above, the seals that are lubricated in the '107 patent do not seal with the tubular. Pub. No. US 2006/0144622 also proposes a system to regulate the pressure between two radial seals. Again, the seals subject to this pressure regulation do not seal with the drill string. The '622 publication also proposes an active sealing element in which fluid is supplied to energize a flexible bladder, and the pressure within the bladder is maintained at a controlled level above the wellbore pressure. The '833 publication proposes an active sealing element in which a hydraulic control maintains the fluid pressure that urges the sealing element toward the drill string at a predetermined pressure above the wellbore pressure. U.S. Pat. No. 7,258,171 proposes a system to pressurize lubricants to lubricate bearings at a predetermined pressure in relation to the surrounding subsea water pressure. Also, U.S. Pat. No. 4,312,404 proposes a system for leak protection of a rotating blowout preventer and U.S. Pat. No. 4,531,591 proposes a system for lubrication of an RCD.
The above discussed U.S. Pat. Nos. 4,312,404; 4,355,784; 4,500,094; 4,531,591; 5,213,158; 5,348,107; 5,647,444; 5,662,181; 5,901,964; 6,016,880; 6,230,824; 6,375,895; 6,547,002; 7,040,394; 7,044,237; 7,237,623; 7,258,171; 7,278,496; 7,367,411; 7,448,454; and 7,487,837; and Pub. Nos. US 2005/0241833; 2006/0144622; 2006/0157282; and 2007/0163784; 2008/0041149; and International Pub. No. WO 2007/092956 or PCT/US2007/061929 are hereby incorporated by reference for all purposes in their entirety. U.S. Pat. Nos. 5,647,444; 5,662,181; 5,901,964; 6,547,002; 7,040,394; 7,237,623; 7,258,171; 7,448,454 and 7,487,837; and Pub. Nos. US 2005/0241833; 2006/0144622; 2006/0157282; and 2007/163784; and International Pub. No. WO 2007/092956 or PCT/US2007/061929 are assigned to the assignee of the present invention.
A need exists for an RCD that can safely operate in dynamic or working conditions in annular wellbore fluid pressures greater than 2500 psi (17,237 kPa). Customers of the drilling industry have expressed a desire for a higher safety factor in both the static and dynamic rating of available RCDs for certain applications. A higher safety factor or dynamic rating would allow for use of RCDs to manage pressurized systems in well prospects with high wellbore pressure, such as in deep offshore wells. It would also be desirable if the design of the RCD complied with API-16RCD requirements. Furthermore, use of the higher rated RCD with a higher surface backpressure with a fluid program that disregards pore pressure and instead uses the fracture pressure of the formation and casing shoe leak off or pressure test as limiting pressure factors would be desirable. This novel drilling limitation variation of MPD would be desirable in that it would allow use of readily available, lighter mud weight and less expensive drilling fluids while drilling deeper with a larger resulting tubular opening area.